The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.
Hydraulic fracturing is the most widely used well stimulation method to enhance hydrocarbon production from oil or gas wells. To achieve the best economical result from a hydraulic fracturing treatment, modern day fracturing treatments commonly involve an extensive design process of acquiring pertinent formation mechanical and stress data, selection of proper fracturing fluid and propping agents, and designing the pumping schedule using a design model. The fracture design model plays a critical role which is to ensure the selected fluids and proppant, their amount, the pump rate and the proppant concentration schedule are all adequate to allow successful proppant placement without premature screenout (or proppant bridging) and to achieve the desired fracture length and conductivity.
Most, if not all, current commercial hydraulic fracture models are based on the assumption of a single hydraulic fracture plane being created in the formation being treated. The fracture initiates from the wellbore and grows in length and height over time as the fluid and proppant are injected into the fracture. The in-situ stress condition in the reservoir is such that there is generally a minimum stress among the three stress components, and the created hydraulic fracture tends to propagate in the plane normal to the minimum stress. This single planar fracture assumption is generally adequate for fracturing treatments in a formation consisting of laterally homogeneous layers.
In recent years, however, fracturing stimulation activities have increased in the unconventional gas shale formations, which contain very large gas reserves. These formations often have extremely low matrix permeability, but contain a large number of natural fractures which provide the apparent permeability for the gas production. Due to the nature of very low permeability, these formations cannot produce without hydraulic fracture stimulation. One of the most successful fracturing techniques applied in gas shale formations to date is the so-called slick water light sand treatment, i.e., a fracture treatment that pumps a very large volume of low-cost slick water with very low proppant concentration. Microseismic mapping conducted during these treatments indicated that a complex network of crisscrossing fractures are created, resulting from the hydraulic fracturing fluid penetrating the existing natural fracture network. Shown in FIG. 1 is microseismic mapping of fracture structures from a treatment in Barnett Shale as reported in Fisher, M. K., Wright, C. A., Davidson, B. M., Goodwin, A. K., Fielder, E. O., Buckler, W. S., and Steinsberger, N. P., “Integrating Fracture Mapping Technologies to Optimize Stimulations in the Barnett Shale,” paper SPE 77441, 2002 SPE Annual Technical Conference and Exhibition, San Antonio, September 29-October 2.
The complex fracture geometry created during these treatments renders the traditional single fracture model completely inadequate in terms of its ability to predict the fracture size or surface area created or the sand placement. While it has been qualitatively established that the gas production of a stimulated well is proportional to the area extent of the created fracture network based on the microseismic measurements, current design tools are not adequate for designing such jobs.
Early hydraulic fracture models are the so-called 2D models. The most widely used 2D models are those described by Perkins, T. K. and Kern, L. R., “Widths of Hydraulic Fractures,” paper SPE 89, Journal of Petroleum Technology (September 1961) 13, No. 9, p. 937-947, which later was extended by Nordren (called PKN model), and by Khristianovich and Geertsma and de Klerk (called KGD model), Geertsma, J. and de Klerk, F., “A Rapid Method of Predicting Width and Extent of Hydraulic Induced Fractures,” paper SPE 2458, Journal of Petroleum Technology (December 1969) 21, 1571-1581. These 2D models consider either a vertical fracture of constant height or a penny-shaped fracture. The 2D models simplify the fracture geometry and reduce the fracture growth to one dimension (either length or radius), making the problem much simpler to solve. The 2D models are suitable to a formation with strong stress barriers above and below to contain the fracture in the zone (typically a sandstone sandwiched between the shales), or a radial fracture propagating in a formation with no stress barriers.
Modern hydraulic fracturing simulators are based on Pseudo-3D (P3D) or full planar 3D models to properly account for fracture height growth. The planar 3D models solve numerically the full set of 3D governing equations to predict the fracture dimensions and the proppant placement in the fracture. These models are computationally intensive and require long computation time, making them less suitable for daily quick job design needs. With today's faster desktop computers, they are increasingly utilized, especially for complex reservoirs where simpler models are not adequate. Most of the commercial fracture design software packages today are based on the P3D models. These models are extensions of the PKN model by considering the fracture height growth. However, the fracture geometry is limited to an ellipse-like shape, and 2D approximation of the fracture surface deformation is made instead of accurately solving the much more complex 3D fracture surface deformation.
Most typical design models simulate a single planar fracture. No fracture branching or interaction with existing natural fractures are possible, which are essential features required in order to simulate the complex fracturing process in the shale gas formation. For a hydraulic fracture system that contains many jointed branches, the lateral fracture penetration is significantly reduced for a given volume of fluid, simply due to mass balance. The fluid loss into the surrounding rock matrix also increases due to the increased surface area, further reducing the fracture penetration. Therefore, the single fracture design model may not provide adequate prediction of the job outcome.
Therefore, there is a need for methods of fracturing naturally fractured subterranean formation using tools which adequately model a fracture network in such formations. This need is met, at least in part, by the following invention.